In some underground petroleum reservoirs the petroleum within the reservoir is of such heavy gravity that even at the temperature of the underground formation the petroleum is immobile and will not flow to a producing well. It has been known to inject into those formations hot liquids or steams with the objective of raising the temperature of the formation to the point where the petroleum within the formation becomes heated to the point where it is mobile enough to be able to flow into a producing well bore.
A large body of technology has developed for the generation of hot fluids or steams at the earth surface and for the injection of those steams or fluids into the subsurface formations. Further, as the cost of energy has increased, more attention has been paid to the efficiency of generating and transporting the hot fluids from the surface to the subsurface formation with the objective of maximizing the input of heat into the formation and minimizing the loss of heat through the conductor carrying the hot fluids from the surface to the subsurface formation.
The subsurface formations that are now becoming targets for secondary recovery or steam stimulation techniques are deeper within the earth's formation than formations that were targets years ago and the chances for loss of thermal energy has substantially increased as the well depth increases. In some of the new target formations two different subsurface formations are candidates for the treatment with hot fluids and these different formations may be separated from each other by substantial distances. Further, each formation may be subject to different injection techniques requiring sometimes different temperatures and different pressures for the injection fluids.
It is usual in the above types of injection techniques that the conducting elements that are placed within the earth formation are of a metallic structure and are placed within the formation at the ambient temperatures of the atmosphere. In the usual case wells are drilled and cased and then steam injection tubing is run into the well and packers are placed between the tubing and the casing above (and sometimes below) the formation to be injected with hot fluids. Each of these operations is conducted at the ambient temperatures (surface or subsurface). After the subsurface well elements have been placed in the formation and the well is ready for steam injection, the wellhead is connected to a steam generator and the hot fluid is pumped down into the formation through the well tubing. As the subsurface well elements are heated to the elevated temperatures of the hot fluid they are subject to expansion and, if the well itself if not properly engineered to accommodate these expansions, the tubing may be damaged or buckled as the expansion forces are exerted between the fixed subsurface connections and the surface wellhead.
The present invention is directed to a wellhead configuration that is adapted to accommodate axial expansion of a hot fluid injection tubing at the wellhead. In accordance with one form of the present invention, a subsurface portion of the injection tubing is fixed in place in preparation for the injection of fluids into the formation while the upper end of the injection tubing may move in response to an axial thermal expansion. A second form of the invention accommodates two injection tubings while allowing one of the tubings to move at the wellhead to accommodate axial thermal expansion.